The term “proppant” is indicative of particulate material which is injected into fractures in subterranean formations surrounding oil wells, gas wells, water wells, and other similar bore holes to provide support to hold (prop) these fractures open and allow gas or liquid to flow through the fracture to the bore hole or from the formation. Proppants are commonly used to prop open fractures formed in subterranean formations such as oil and natural gas wells during hydraulic fracturing.
Uncoated and/or coated particles are often used as proppants to keep open fractures imposed by hydraulic fracturing upon a subterranean formation, e.g., an oil or gas bearing strata.
The uncoated proppants are typically particles of sand or a variety of ceramics, as known in the art. Particles used to prop fractures generally comprise sand or sintered ceramic particles. The advantage of sand is that it is inexpensive. Its disadvantages are its relatively low strength (high crush values) and lower flow capacities than sintered ceramic particles. Sintered ceramic particles are also used as proppants. The ceramic particles are disadvantageous in that the sintering is carried out at high temperatures, resulting in high production costs. In addition, expensive raw materials are used. These two factors combine to make ceramic proppant an expensive alternative. Some versions of the ceramic proppant also have increased apparent densities (as compared to sand) which translates to more difficulty in carrying the proppant out into the fracture and requiring more pounds of proppant to fill the created fracture volume.
The coated proppants have individual particles coated with a resin. The individual particles are typically particles of sand, ceramics, glass beads, walnut shells, etc. as known in the art. The proppant coatings may be precured or curable. The precured proppants include a substrate core and a coating of resin cured prior to insertion into the subterranean formation. The curable proppants include a substrate core and a coating of resin at least partially cured downhole to form a consolidated proppant pack. Resin formulations typically used for curable coatings on proppant substrates (sand, ceramic, etc.) result in a highly crosslinked coating on the surface of the substrates.
Curable resin coated proppants and precured resin coated proppants have been commercially available for use as propping agents. A curable proppant has a resin coating that includes a resin that is usually at least partially, and but not fully, cured. In contrast, a “precured” proppant has a cured resin coating.
The terms “cured” and “curable” are defined for the present specification by three tests historically employed in the art.
Temperature Stick Point Test: placing coated material on a heated melt point bar and determining the lowest temperature at which the coated material adheres to the melt point bar. A “sticking temperature” of greater than 350° F., typically indicates a cured material, depending upon the resin system used.
Acetone Extraction Test: an acetone extraction method, as described below, to dissolve the fraction of resin within the coating that is uncured.
Compressive Strength Test: no bonding, or no consolidation of the coated particles, following wet compression at atmospheric pressure at 200° F. for a period of as much as 24 hours, typically indicates a cured material. However, a precured resin coating does not mean the coating has zero curability left in it. Precured coatings are coatings such that the coated particles do not have the ability to generate significant particle to particle bond strength, thus less than 10 psi bond strength when subjected to moderate conditions of temperature (<200° F.) and atmospheric pressure closure stress. Typically the wet compression test is performed on a 12 pounds per gallon slurry in 2% KCl.
However, unless otherwise indicated, the terms cured and curable are defined by the Compressive Strength Test.
For purposes of this application, the term “cured” and “crosslinked” are used interchangeably for the hardening which occurs in an organic binder. However, the term “cured” also has a broader meaning in that it generally encompasses the hardening of any binder, organic or inorganic, to form a stable material. For example, crosslinking, ionic bonding and/or removal of solvent to form a bonded material in its final hardened form may be considered curing. Thus, mere removal of solvent from an organic binder prior to crosslinking may or may not be curing depending upon whether the dry organic binder is in final hardened form.
Proppants are generally used to increase production of oil and/or gas by providing a conductive channel in the formation. Fracturing of the subterranean formation is conducted to increase oil and/or gas production. Fracturing is caused by the injection of a fluid (either a hydrocarbon, water, foam or emulsion) into a formation at a rate that exceeds the formation's ability to accept the flow. The inability for the formation to dissipate the fluid results in a buildup of pressure. When this pressure buildup exceeds the strength of the formation rock, a fracture is initiated. Continued pumping of the fracturing fluid will result in the fracture growing in length, width and height. The rate required to initiate and extend the fracture is related to the injection rate and viscosity of the fracturing fluid. This combination of injection rate and fluid viscosity is also a critical factor in the ability of the fracturing fluid to transport the proppant to the most distance points of the fracture geometry being created. As the fracture is formed, a particulate material, referred to as a “propping agent” or “proppant” is placed in the formation to maintain the fracture in a propped condition when the injection pressure is released. As the fracture forms, the proppants are carried into the fracture by suspending them in additional fluid or foam to fill the fracture with a slurry of proppant in the fluid or foam. Upon ceasing the injection of fluid, the proppants form a pack that serves to hold open the fractures. The propped fracture thus provides a highly conductive channel in the formation. The degree of stimulation afforded by the hydraulic fracture treatment is largely dependent upon formation parameters, the fracture's permeability, the propped fracture length, propped fracture height and the fracture's propped width.
When the oilfield industry “fractures” hydrocarbon bearing formations, the use of proppants to retain the high surface area created by the fracture has become common practice. It is highly desirable that the proppant particles are of high performance and can be produced in highly efficient processes (are economically attractive) with minimal investment capital and at remote sites (such as existing transloads).
WO 2008/088449 explains there have been several studies related to increasing the fracture resistance or toughness of epoxy resins by adding to the epoxy resin various block copolymers as toughening agent. Much of the work is focused on the use of amphiphilic diblock copolymers having an epoxy miscible block and an epoxy immiscible block. In those studies, the epoxy miscible block is poly(ethylene oxide) (“PEO”) and the immiscible block is a saturated polymeric hydrocarbon. For example, Journal of Polymer Science, Part B: Polymer Physics, 2001, 39(23), 2996-3010 discloses that the use of a polyethylene oxide)-b-poly(ethylene-alt-propylene) (“PEO-PEP”) diblock copolymer provides micellar structures in cured epoxy systems; and that block copolymers self-assembled into vesicles and spherical micelles can significantly increase the fracture resistance of model bisphenol A epoxies cured with a tetrafunctional aromatic amine curing agent. Journal of The American Chemical Society, 1997, 119(11), 2749-2750 describes epoxy systems with self-assembled microstructures brought about using amphiphilic PEO-PEP and poly(ethylene oxide)-b-poly(ethyl ethylene) (“PEO-PEE”) diblock copolymers. These block copolymer containing-systems illustrate characteristics of self-assembly. Although effective at providing templated epoxies with appealing property sets, the known block copolymer materials are too expensive to be used in some applications. Other block copolymers incorporating an epoxy-reactive functionality in one block have been used as modifiers for epoxy resins to achieve nanostructured epoxy thermosets. For example, Macromolecules, 2000, 33(26) 9522-9534 describes the use of poly(epoxyisoprene)-b-polybutadiene (“Blxn”) and poly(methylacrylate-co-glycidyl methacrylate)-b-polyisoprene (“MG-I”) diblock copolymers that are amphiphilic in nature and are designed in such a way that one of the blocks can react into the epoxy matrix when the, resin is cured. Journal of Applied Polymer Science, 1994, 54, 815 describes epoxy systems having submicron scale dispersions of poly(caprolactone)-b-poly(dimethylsiloxane)-b-poly(caprolactone) triblock copolymers. Other self-assembled amphiphilic block copolymers for modifying thermosetting epoxy resins to form nanostructured epoxy thermosets are known. For example, Macromolecules 2000, 33, 5235-5244 and Macromolecules, 2002, 35, 3133-3144, describe the addition of a poly(ethylene oxide)-b-poly(propylene oxide) (“PEO-PPO”) diblock and a poly(ethylene oxide)-b-poly(propylene oxide)-b-poly(ethylene oxide) (“PEO-PPO-PEO”) triblock to an epoxy cured with methylene dianiline, where the average size of the dispersed phase in the diblock-containing blends is of the order of 10-30 nm. A polyether block copolymer such as a PEO-PPO-PEO triblock is also known to be used with an epoxy resin as disclosed in JP H9-324110. While some of the previously known diblock and triblock copolymers mentioned above are useful for improving the toughness of epoxy resins, none of them were used in proppant applications in hydraulic fracturing.
WO 2008/088449 discloses a coated proppant, having a toughening agent in its coating, which comprises of a proppant particulate substrate and a coating layer on the substrate. The coating layer is formed from a coating composition which comprises a resin, a curing agent, an adhesion promoter, and a toughening agent. In the coating composition, the resin may be an epoxy resin or a phenolic resin or a mixture thereof. In the coating composition, the curing agent may be one or more of a) an aliphatic or modified aliphatic amine, b) aromatic amine, c) a cycloaliphatic or modified cyclophatic amine, d) an anhydride, e) Lewis acid like boron triflouride or f) a hexamethylenetetramanine compound. In the coating composition, the toughening agent may be any one of the commercially available toughening agents. There are a number of commercial toughening agents available such as carboxyl-terminated copolymer of butadiene and acrylonitrile liquid rubber and other functionalize liquid rubbers. Some core-shell rubber can also be added to the epoxy resin as toughening agents. For example, CTBN from Novean and ICANE ACE MX-117 from Kaneka Corporation may be used as toughening agents on proppants. In preferred embodiments, a block amphiphilic block copolymer is used. The amphiphilic block copolymer contains at least one epoxy resin miscible block segment and at least one epoxy resin immiscible block segment. The immiscible block segment may comprise at least one polyether structure provided that the polyether structure of the immiscible block segment contains at least one or more alkylene oxide monomer units having at least four carbon atoms. In one preferred embodiment of the present invention, XU 19110 epoxy resin from The Dow Chemical Company is used. The XU 19110 is a toughened liquid epoxy resin and contains a standard Bisphenol-A epoxy resin blended with a toughening agent. This product is a blend of about 95 wt % standard Bisphenol-A epoxy resins and about 5 wt. % of toughening agent such as amphibilic block copolymer. The EEW value of XU 19110 is between 192-202 measured with ASTM D-1652.